Clean Viscosified Treatment Fluids and Associated Methods

ABSTRACT

Treatment fluids comprising an aqueous base fluid, a viscosifying agent, and a compliant dual-functional additive are provided. The present invention provides methods of using the treatment fluids in subterranean formations. One example of a suitable method includes providing a fracturing fluid comprising an aqueous base fluid, a viscosifying agent, and a compliant dual-functional additive that acts as a fluid loss control agent and a breaker and introducing the fracturing fluid into at least a portion of a subterranean formation at a rate and pressure sufficient to create or enhance at least one or more fractures in the subterranean formation.

BACKGROUND OF THE INVENTION

The present invention relates to fluids useful for subterraneanoperations, and more particularly, to treatment fluids comprising acompliant dual-functional additive and a viscosifying agent, and methodsof use employing such treatment fluids to treat subterranean formations.

Aqueous treatment fluids may be used in a variety of subterraneantreatments. Such treatments include, but are not limited to, stimulationoperations and completion operations. As used herein, the term“treatment,” or “treating,” refers to any subterranean operation thatuses a fluid in conjunction with a desired function and/or for a desiredpurpose. The term “treatment,” or “treating,” does not imply anyparticular action by the fluid.

An example of a subterranean treatment using an aqueous treatment fluidis hydraulic fracturing. In a hydraulic fracturing treatment, a viscousfracturing fluid is introduced into the formation at a high enough rateto exert a sufficient pressure on the formation to create and/or extendfractures therein. The viscous fracturing fluid suspends proppantparticles that are to be placed in the fractures to prevent thefractures from fully closing (once the hydraulic pressure is released),thereby forming conductive channels within the formation through whichhydrocarbons can flow toward the well bore for production. In certaincircumstances, a portion of the fracturing fluid may be lost during thefracturing operation, e.g., through undesirable leakoff into naturalfractures present in the formation. Typically, operators have attemptedto solve this problem by including a fluid loss control additive in thefracturing fluid. Many conventional fluid loss control additivespermanently reduce the permeability of a subterranean formation,negatively affect the rheology of the treatment fluid in which they areused, and/or reduce the rate at which the fluid is allowed to penetrateor leak off into desirable locations within the subterranean formation.Moreover, while it may be desirable to control or prevent fluid loss fora given period of time, in some instances it may become desirable tolater allow a treatment fluid to penetrate or leak off into that portionof the subterranean formation. Thus, costly and time-consumingoperations may be required to reverse the effects of conventional fluidloss control additives on the treatment fluid and/or to restorepermeability to those portions of the subterranean formation affected bythe fluid loss control additives.

Once at least one fracture is created and at least a portion of theproppant is substantially in place, the viscosity of the treatment fluidmay be reduced, to facilitate removal from the formation. This viscosityreduction or conversion is referred to as “breaking” and can beaccomplished by incorporating chemical agents, referred to as“breakers,” into the initial gel. Common breakers include oxidants orenzymes that operate to degrade the polymeric gel structure of theviscous treatment fluids. Common oxidizing agents used as breakersinclude persulfate salts (either used as is or encapsulated), organicperoxides, or alkaline earth and zinc peroxide salts. The timing of thebreak is also of great importance. Gels that break prematurely can leadto a premature reduction in the fluid viscosity, resulting in a lessthan desirable fracture width in the formation causing excessiveinjection pressures and premature termination of the treatment. On theother hand, gelled fluids that break too slowly can cause slow recoveryof the fracturing fluid from the produced fracture with attendant delayin resuming the production of formation fluids and severely impairanticipated hydrocarbon production.

Numerous additives are used in the art to help control fluid loss or tobreak the viscosity of a treatment fluid in subterranean operations.However, the use of these conventional additives may give rise to otherproblems. First, the necessity of both a fluid loss control additive anda separate breaker additive in a treatment fluid may increase thecomplexity and cost of a treatment fluid and/or a subterraneanapplication using that fluid. In some instances, the fluid loss controladditives and breaker additives used are toxic and thus may harm theenvironment; this problem may be aggravated because many are poorlydegradable or nondegradable within the environment. Due to environmentalregulations, costly procedures often must be followed to dispose of thetreatment fluids containing such compounds, ensuring that they do notcontact the marine environment and groundwater. Thus, it is desirable touse low environmental impact additives for treatment fluids. It wouldalso be desirable to reduce the number of additives needed in atreatment fluid.

SUMMARY OF THE INVENTION

The present invention relates to fluids useful for subterraneanoperations, and more particularly, to treatment fluids comprising acompliant dual-functional additive and a viscosifying agent, and methodsof use employing such treatment fluids to treat subterranean formations.

In one embodiment, the methods of the present invention comprise:providing a treatment fluid comprising an aqueous base fluid, aviscosifying agent, and a compliant dual-functional additive that actsas a fluid loss control agent and a breaker; and introducing thetreatment fluid into at least a portion of the subterranean formation.

In another embodiment, the methods of the present invention comprise:providing a fracturing fluid comprising an aqueous base fluid, aviscosifying agent, and a compliant dual-functional additive that actsas a fluid loss control agent and a breaker; and introducing thetreatment fluid into at least a portion of a subterranean formation at arate and pressure sufficient to create or enhance at least one or morefractures in the subterranean formation.

In yet another embodiment, the methods of the present inventioncomprise: providing a treatment fluid comprising an aqueous base fluid,a viscosifying agent, and a compliant dual-functional additive thatcomprises a fluid loss control agent and a breaker; introducing thetreatment fluid into at least a portion of the subterranean formation;and allowing the dual-functional additive to minimize fluid loss byobstructing at least one pore throat opening in the subterraneanformation.

Other features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 shows the effect of triethyl citrate (TEC) with and without ethylformate (EF) on the viscosity of the treatment fluid.

FIG. 2 shows the dynamic fluid loss of the treatment fluid with andwithout triethyl citrate.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to fluids useful for subterraneanoperations, and more particularly, to treatment fluids comprising acompliant dual-functional additive and a viscosifying agent, and methodsof use employing such treatment fluids to treat subterranean formations.

The treatment fluids of the present invention may comprise a compliantdual-functional additive that acts as a fluid loss control agent and aviscosity reducing agent for the treatment fluids. As used herein, theterm “compliant” refers to materials described in 21 CFR §§170-199(substances approved as food items, approved for contact for food, orapproved for use as an additive to food) and that are prepared fromfood-grade materials

Of the many advantages of the compositions and related methods of thepresent invention, is that treatment fluids of the present invention mayimprove oil and/or gas production by using dual-functional additives andreducing the number of additives required in a treatment fluid. Thedual-functional additives suitable for use in the present inventionprovide both fluid loss control and the ability to break the viscosityof the treatment fluid in which they are used over time. Theself-degrading fluid loss control properties and the delayed-releasebreaking properties may lead to better conductivity in the treatedportion of the subterranean formation. In certain embodiments, thesedual-functional additives may reduce or eliminate the need for separate,multiple additives to provide fluid loss control and viscosity break.Moreover, the dual-functional additives suitable for use in the presentinvention have self-degrading properties whereby they may form aself-degrading filter cake that both reduces fluid loss and eliminatesthe need for a secondary solution to dissolve the filter cake after thesubterranean operation is complete. In fact, in certain embodiments, thecompliant dual-functional additives of the present invention maypotentially eliminate the need for costly procedures needed to disposeof the treatment fluids containing non-compliant additives and may helpreduce negative impacts on the marine environment and groundwater.Additionally, compliant dual-functional additives according to thepresent invention may provide effective treatment of the formationwithout excessive damage caused by the use of multiple or non-compliantadditives.

In accordance with embodiments of the present invention, the treatmentfluids generally comprise an aqueous base fluid, a viscosifying agent,and a compliant dual-functional additive that acts as both a fluid losscontrol agent and a viscosity reducing agent for the treatment fluids.

By way of example, the aqueous base fluid of embodiments of thetreatment fluids of the present invention may be any fluid comprising anaqueous component. Suitable aqueous components include, but not limitedto, fresh water, salt water, brine (e.g., saturated or unsaturatedsaltwater), seawater, pond water and any combination thereof. Generally,the aqueous component may be from any source. Suitable aqueous basefluids may include foams. In certain embodiments, the viscosifyingagents of the present invention may be difficult to dissolve in brines.To solve this problem, in one embodiment of the present invention, theviscosifying agent may be hydrated in fresh water prior to addition ofthe salt solution. One of ordinary skill in the art, with the benefit ofthe present disclosure, will recognize suitable aqueous base fluids foruse in the treatment fluids and methods of the present invention. Insome embodiments, the aqueous base fluid may be present in a treatmentfluid of the present invention in an amount in the range of about 75% toabout 99.9% of the treatment fluid. In some embodiments, fresh water maybe the preferred aqueous base fluid.

The viscosifying agent of the present invention may be any suitableviscosifying agent that may perform the desired function. Suitableviscosifying agents may comprise any substance (e.g. a polymericmaterial) capable of increasing the viscosity of the treatment fluids.In certain embodiments, the viscosifying agent may comprise one or morepolymers that have at least two molecules that are capable of forming acrosslink in a crosslinking reaction in the presence of a crosslinkingagent, and/or polymers that have at least two molecules that arecrosslinked (i.e., a crosslinked viscosifying agent). The viscosifyingagents may be biopolymers, polysaccharides, and/or derivatives thereofthat contain one or more of these monosaccharide units: galactose,mannose, glucose, xylose, arabinose, fructose, glucuronic acid, orpyranosyl sulfate. The term “derivative” includes any compound that ismade from one of the listed compounds, for example, by replacing oneatom in the listed compound with another atom or group of atoms,rearranging two or more atoms in the listed compound, ionizing one ofthe listed compounds, or creating a salt of one of the listed compounds.Examples of suitable viscosifying agents include, but are not limitedto, cellulose derivatives, carboxymethylguars,carboxymethylhydroxyethylguars, carboxymethylhydroxypropylguars,hydroxyethylcelluloses, carboxyethylcelluloses, carboxymethylcelluloses,carboxymethylhydroxyethylcelluloses, diutan gums, xanthan gums,galactomannans, hydroxyethylguars, hydroxypropylguars, scleroglucans,wellans, starches (also known as polysaccharide gums), and anyderivative and combination thereof. In some embodiments a compliantviscosifying agent may be used, examples of suitable compliantviscosifying agents include carboxyethylcellulose,carboxymethylcellulose (CMC), carboxymethylhydroxyethylcellulose, andcombination thereof.

The viscosifying agent may be present in the treatment fluids useful inthe methods of the present invention in an amount sufficient to providethe desired viscosity. In some embodiments, the viscosifying agents maybe present in an amount in the range of from about 0.01% to about 10% byweight of the treatment fluid. In other embodiments, the viscosifyingagents may be cellulose derivatives present in an amount in the range offrom about 0.1% to about 1% by weight of the treatment fluid. In otherembodiments, the viscosifying agents may be starches present in therange of from about 3% to 5% by weight of the treatment fluid. In otherembodiments, the viscosifying agents may be polysaccharides present fromabout 0.1% to 3% by weight of the treatment fluid. In some embodimentsthe viscosifying agent may be a mixture of a polysaccharide and a starch(as used herein, the term “starch” refers to a polysaccharide gum).

The compliant dual-functional additives suitable for use in the presentinvention may comprise any substance initially capable of preventingfluid loss of the treatment fluids by obstructing pore throats in thesubterranean formation and subsequently capable of decreasing theviscosity of the treatment fluids through a double reaction mechanism.In certain embodiments, the dual-functional agent may comprise compoundsthat include any compliant ester capable of preventing fluid loss andbreaking the viscous fluid in a controlled manner after well treatmentis completed. An ester compound is defined as a compound that includesone or more carboxylate groups: R1—COO—R2, wherein R1 can be H andwherein R1 and R2 may be phenyl, methoxyphenyl, alkylphenyl, C1-C11alkyl, C1-C.11 substituted alkyl, substituted phenyl, or other organiccompound. Suitable esters include, but are not limited to, diesters,triesters, etc. Generally, suitable compliant dual-functional additivesare immiscible in the treatment fluids and yet are capable ofhydrolyzing over time in the presence of the water in the treatmentfluid. Examples of suitable compliant esters include, but are notlimited to, ethyl formate, propyl formate, butyl formate, amyl formate,anisyl formate, methyl acetate, propyl acetate, triacetin, butylpropionate, isoamyl propionate, ethyl lactate, methyl butyrate, ethylisobutyrate, butyl isobutyrate, diethyl malonate, butyl ethyl malonate,dimethyl succinate, diethyl succinate, diethyl malate, diethyl tartrate,dimethyl tartrate, triethyl citrate, and any derivative and combinationthereof. Suitable esters may include either substituted or unsubstitutedalkyl groups.

In certain embodiments, a suitable dual-functional additive is an estercompound that degrades to form an acid thereby allowing the acid to actas a viscosity reducing agent for the treatment fluid. Suitable acidsfor use in the present invention include any compliant acid into whichthe compliant esters may degrade. Examples of such acids include, butare not limited to, formic acid, acetic acid, propionic acid, lacticacid, butyric acid, isobutyric acid, malonic acid, succinic acid, malicacid, tartaric acid, citric acid, and any combination thereof.

Without being limited by theory, it is believed that in certainembodiments the dual-functional additives provide fluid-loss controluntil the esters degrade into water-soluble components that subsequentlybreak the viscosity of the treatment fluids through a double reactionmechanism, which may include both a hydrolysis reaction and a chelationreaction. By way of example, the dual-functional additive may catalyzehydrolysis of portions of the polymer backbone, and chelate crosslinkingmetal species that may be present; thereby reducing the viscosity. Thecombination of a degradable fluid-loss control agent and a delayedbreaker may result in very low permeability damage and high conductivityonce the reaction is complete. In certain embodiments, the hydrolysis ofthe compliant dual-functional additives is dependent on the pH range ofthe treatment fluid and the solubility of the ester. In certainembodiments, the alkyl group of the ester that comes from thecorresponding alcohol may control the solubility properties of theester. By way of example, one skilled in the art will recognize thatesters made from low carbon number alcohols, such as methanol andethanol, generally have relatively higher water solubility. Thus,application temperature range for these esters may be lower than highercarbon atom esters. For higher temperature applications, esters formedfrom higher carbon number alcohols, such as n-propanol, butanol,hexanol, and cyclohexanol, may be more suitable. In other embodiments,esters formed from polycarboxylic acids may be well suited for use inhigh temperature applications. In certain embodiments, mixed esters withboth high and low carbon numbers, may be used for high temperatureapplications (for example, 275° F. or above when using triethyl citrate)to achieve a more rapid viscosity break in the treatment fluids. Mixedesters may also be beneficial for moderate temperature applications (forexample, 275° F. or below when using triethyl citrate). For example,combining a formate ester with triethyl citrate will increase the rateof hydrolysis of the triethyl citrate in a pH range from about 3.5 toabout 5. In those embodiments, combining both formate and acetate estersmay lead to a faster break in the viscosity of the treatment fluid. Oneof ordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate ester or combination of esters to include in atreatment fluid of the present invention based on, among other things,the temperature conditions of a particular application, the type ofviscosifying agents used, the molecular weight of the viscosifyingagents, the desired degree of viscosification, and the pH of thetreatment fluid.

A compliant dual-functional additive may be present in the treatmentfluids useful in the methods of the present invention in an amountsufficient to provide the desired effect. That is, sufficient to provideat least a portion of the desired fluid loss control and breaker action.In some embodiments, the dual-functional additives may be present in anamount in the range of from about 0.03% to about 3% by weight of thetreatment fluid. In other embodiment, the dual-functional additives maybe present in an amount in the range of from about 0.1% to about 1% byweight of the treatment fluid.

In certain embodiments, the treatment fluids of the present inventionmay be a foamed fluid (e.g., a liquid that comprises a gas such asnitrogen, carbon dioxide, air, or methane). As used herein, the term“foamed” also refers to fluids such as commingled fluids. In someembodiments, a foamed treatment fluid may be desirable to, among otherthings, reduce the amount of fluid that is required in a water sensitivesubterranean formation, to reduce fluid loss in the formation, and/or toprovide enhanced proppant suspension. In examples of such embodiments,the gas may be present in the range of from about 5% to about 98% byvolume of the treatment fluid, and more preferably in the range of fromabout 20% to about 80% by volume of the treatment fluid. The amount ofgas to incorporate in the fluid may be affected by many factorsincluding the viscosity of the fluid and the wellhead pressures involvedin a particular application. One of ordinary skill in the art, with thebenefit of this disclosure, will recognize the how much gas, if any, toincorporate into the treatment fluids of the present invention.

Depending on the use of the treatment fluid, in some embodiments, otheradditives may optionally be included in the treatment fluids of thepresent invention. Examples of such additives may include, but are notlimited to, salts, pH control additives, surfactants, additionalbreakers, biocides, crosslinkers, additional fluid loss control agents,stabilizers, chelating agents, scale inhibitors, gases, mutual solvents,particulates, corrosion inhibitors, oxidizers, reducers, and anycombination thereof. A person of ordinary skill in the art, with thebenefit of this disclosure, will recognize when such optional additivesshould be included in a treatment fluid used in the present invention,as well as the appropriate amounts of those additives to include.

In those embodiments of the present invention where it is desirable tocrosslink the viscosifying agent, the treatment fluid may comprise oneor more crosslinking agents. The crosslinking agents may comprise ametal ion or similar component that is capable of crosslinking at leasttwo molecules of the viscosifying agent. Examples of suitablecrosslinking agents include, but are not limited to, magnesium ions,zirconium ions, titanium ions, aluminum ions, antimony ions, chromiumions, iron ions, copper ions, magnesium ions, and zinc ions. These ionsmay be provided by providing any compound that is capable of producingone or more of these ions as is well understood by those of skill in theart. Examples of such compounds include, but are not limited to, ferricchloride, magnesium oxide, zirconium lactate, zirconium triethanolamine,zirconium lactate triethanolamine, zirconium carbonate, zirconiumacetylacetonate, zirconium malate, zirconium citrate, zirconiumdiisopropylamine lactate, zirconium glycolate, zirconium acetatelactate, zirconium triethanolamine glycolate, zirconium lactateglycolate, zirconium triisopropanolamine lactate, titanium lactate,titanium malate, titanium citrate, titanium ammonium lactate, titaniumtriethanolamine, and titanium acetylacetonate, aluminum lactate,aluminum citrate, aluminum acetate, antimony compounds, chromium(III)compounds, iron(II) compounds, iron(III) compounds, copper compounds,zinc compounds, and combinations thereof. In certain embodiments of thepresent invention, the crosslinking agent may be formulated to remaininactive until it is “activated” by, among other things, certainconditions in the fluid (e.g., pH, temperature, etc.) and/or interactionwith some other substance.

In some preferred embodiments, a compliant crosslinking agent may beused. Examples of suitable compliant crosslinking metal ions (that is,ions capable of crosslinking) include, but are not limited to, zirconiumcompounds contained within 21 CFR §§170-199, aluminum compoundscontained within 21 CFR §§170-199, titanium compounds contained within21 CFR §§170-199, chromium(III) compounds contained within 21 CFR§§170-199, iron(II) compounds contained within 21 CFR §§170-199,iron(III) compounds contained within 21 CFR §§170-199, copper compoundscontained within 21 CFR §§170-199, zinc compounds contained within 21CFR §§170-199, and combinations thereof. Examples of such suitablecompliant ion-containing compounds include but are not limited toammonium zirconium carbonate, zirconium citrate, zirconium lactatecitrate, zirconium oxide, titanium dioxide, aluminum nicotinate,aluminum sulfate, aluminum sodium sulfate, aluminum ammonium sulfate,chromium caseinate, chromium potassium sulfate, zinc sulfate, zinchydrosulfite, magnesium chloride, magnesium sulfate, magnesiumgluconate, copper sulfate, and copper gluconate.

When included, suitable crosslinking agents may be present in thetreatment fluids useful in the methods of the present invention in anamount sufficient to provide a desired degree of crosslinking betweenmolecules of the viscosifying agent. In certain embodiments, thecrosslinking agent may be present in the treatment fluids of the presentinvention in an amount in the range of from about 0.005% to about 1% byweight of the treatment fluid. In other embodiments, the crosslinkingagent may be present in the treatment fluids of the present invention inan amount in the range of from about 0.05% to about 0.1% by weight ofthe first treatment fluid and/or second treatment fluid. Whilecrosslinking agents may be added in a concentrated solution, thenumerical ranges given above refer to the percentage of metal ions byweight of the treatment fluid. One of ordinary skill in the art, withthe benefit of this disclosure, will recognize the appropriate amount ofcrosslinking agent to include in a treatment fluid of the presentinvention based on, among other things, the temperature conditions of aparticular application, the type of viscosifying agents used, themolecular weight of the viscosifying agents, the desired degree ofviscosification, and/or the pH of the treatment fluid.

It generally takes greater horsepower to pump fluids that are moreviscous; thus, it may be desirable to delay the crosslink of thetreatment fluids of the present invention until the fluid is close tothe area to be treated. Such delay allows the operator to pump anon-crosslinked (and thus less viscous) fluid over a longer distancebefore having to add horsepower to place the more viscous, crosslinkedfluid. One skilled in the art will be familiar with known methods todelay crosslinking, such as encapsulation, chemical delays (e.g.chelating agents), etc. In some embodiments, the activation of thecrosslinking agent may be delayed by encapsulation with a coating (e.g.,a porous coating through which the crosslinking agent may diffuse slowlyor a degradable coating that degrades down hole) that delays the releaseof the crosslinking agent until a desired time or place. In otherembodiments, chelating agents, such as lactic acid and oxalic acid, maybe added to delay the crosslinking of the viscosifying agent.

The treatment fluids of the present invention may comprise particulates,such as proppant particulates or gravel particulates. Such particulatesmay be included in the treatment fluids of the present invention, forexample, when a gravel pack is to be formed in at least a portion of thewell bore, or a proppant pack is to be formed in one or more fracturesin the subterranean formation. Particulates suitable for use in thepresent invention may comprise any material suitable for use insubterranean operations. Suitable materials for these particulates mayinclude, but are not limited to, sand, bauxite, ceramic materials, glassmaterials, polymer materials, polytetrafluoroethylene materials(commonly sold under the trade name TEFLON®), nut shell pieces, curedresinous particulates comprising nut shell pieces, seed shell pieces,cured resinous particulates comprising seed shell pieces, fruit pitpieces, cured resinous particulates comprising fruit pit pieces, wood,composite particulates, and combinations thereof. Suitable compositeparticulates may comprise a binder and a filler material whereinsuitable filler materials include silica, alumina, fumed carbon, carbonblack, graphite, mica, titanium dioxide, calcium silicate, kaolin, talc,zirconia, boron, fly ash, hollow glass microspheres, solid glass, andcombinations thereof. The mean particulate size generally may range fromabout 2 mesh to about 400 mesh on the U.S. Sieve Series; however, incertain circumstances, other mean particulate sizes may be desired andwill be entirely suitable for practice of the present invention. Inparticular embodiments, preferred mean particulate size distributionranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60,40/70, or 50/70 mesh. It should be understood that the term“particulate,” as used in this disclosure, includes all known shapes ofmaterials, including substantially spherical materials, fibrousmaterials, polygonal materials (such as cubic materials), and mixturesthereof. Moreover, fibrous materials, that may or may not be used tobear the pressure of a closed fracture, may be included in certainembodiments of the present invention. In certain embodiments, theparticulates included in the treatment fluids of the present inventionmay be coated with any suitable resin or tackifying agent known to thoseof ordinary skill in the art. In certain embodiments, the particulatesmay be present in the treatment fluids of the present invention in anamount in the range of from about 0.5 pounds per gallon (“ppg”) to about30 ppg by volume of the treatment fluid.

A biocide may be included to the treatment fluids of the presentinvention to reduce bioburden of the fluid so as to avoid introducing anundesirable level of bacteria into the subterranean formation. Suitableexamples of biocides may include both oxidizing biocides andnonoxidizing biocides. Examples of oxidizing biocides include, but arenot limited to, sodium hypochlorite, hypochlorous acid, chlorine,bromine, chlorine dioxide, and hydrogen peroxide. Examples ofnonoxidizing biocides include, but are not limited to, aldehydes,quaternary amines, isothiazolines, carbamates, phosphonium quaternarycompounds, and halogenated compounds. Factors that determine whatbiocide will be used in a particular application may include, but arenot limited to, cost, performance, compatibility with other componentsof the treatment fluid, kill time, and environmental compatibility. Oneskilled in the art with the benefit of this disclosure will be able tochoose a suitable biocide for a particular application.

In some embodiments, UV radiation may be used to reduce the bioburden ofa fluid in place of chemical biocides or used in conjunction withchemical biocides. One method of using UV light to reduce bioburdensuitable for use in the present invention involves adding aphotoinitiator to the treatment fluid and then exposing the treatmentfluid to a UV light source. Such photoinitiators may absorb the UV lightand undergo a reaction to produce a reactive species of free radicalsthat may in turn trigger or catalyze desired chemical reactions.Suitable organic photoinitiators for use in the present invention mayinclude, but are not limited to, acetophenone, propiophenone,benzophenone, xanthone, thioxanthone, fluorenone, benzaldehyde,anthraquinone, carbazole, thioindigoid dyes, phosphine oxides, ketones,benzoin ethers, benzyl ketals, alpha-dialkoxyacetophenones,alpha-hydroxyalkylphenones, alpha-aminoalkylphenones, and acylphosphineoxides; any combination or derivative thereof. Suitable inorganicphotoinitiators for use in the present invention are substances that,when exposed to UV light, will generate free radicals that will interactwith the microorganisms as well as other organics in a given treatmentfluid. Some suitable inorganic photoinitiators include, but are notlimited to, nanosized metal oxides (e.g., those that have at least onedimension that is 1 nm to 1000 nm in size) such as titanium dioxide,iron oxide, cobalt oxide, chromium oxide, magnesium oxide, aluminumoxide, copper oxide, zinc oxide, manganese oxide, and any combination orderivative thereof.

Salts may optionally be included in the treatment fluids of the presentinvention for many purposes, including, for reasons related tocompatibility of the treatment fluid with the formation and formationfluids. To determine whether a salt may be beneficially used forcompatibility purposes, a compatibility test may be performed toidentify potential compatibility problems. From such tests, one ofordinary skill in the art with the benefit of this disclosure will beable to determine whether a salt should be included in a treatment fluidof the present invention. Suitable salts include, but are not limitedto, calcium chloride, sodium chloride, magnesium chloride, potassiumchloride, sodium bromide, potassium bromide, ammonium chloride, sodiumformate, potassium formate, cesium formate, mixtures thereof, and thelike. The amount of salt that should be added should be the amountnecessary for formation compatibility, such as stability of clayminerals, taking into consideration the crystallization temperature ofthe brine, e.g., the temperature at which the salt precipitates from thebrine as the temperature drops.

Examples of suitable pH control additives that may optionally beincluded in the treatment fluids of the present invention are basesand/or acid compositions. A pH control additive may be necessary tomaintain the pH of the treatment fluid at a desired level, e.g., toimprove the effectiveness of certain breakers and crosslinkers, etc. Insome instances, it may be beneficial to maintain the pH at 3.5-5. One ofordinary skill in the art with the benefit of this disclosure will beable to recognize a suitable pH for a particular application.

In one embodiment, the pH control additive may be an acid composition.Examples of suitable acid compositions may comprise an acid, an acidgenerating compound, and combinations thereof. Any known acid may besuitable for use with the treatment fluids of the present invention.Examples of acids that may be suitable for use in the present inventioninclude, but are not limited to organic acids (e.g., formic acids,acetic acids, carbonic acids, citric acids, glycolic acids, lacticacids, ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediamine triacetic acid (HEDTA), and the like), inorganic acids(e.g., hydrochloric acid, hydrofluoric acid, phosphonic acid,p-toluenesulfonic acid, and the like), and combinations thereof.

Examples of acid generating compounds that may be suitable for use inthe present invention include, but are not limited to, esters, aliphaticpolyesters, ortho esters, which may also be known as ortho ethers,poly(ortho esters), which may also be known as poly(ortho ethers),poly(lactides), poly(glycolides), poly(ε-caprolactones),poly(hydroxybutyrates), poly(anhydrides), or copolymers thereof. Theterm “copolymer” as used herein is not limited to the combination of twopolymers, but includes any combination of polymers, e.g., terpolymersand the like. Derivatives and combinations also may be suitable. Othersuitable acid-generating compounds include: esters including, but notlimited to, ethylene glycol monoformate, ethylene glycol diformate,diethylene glycol diformate, glyceryl monoformate, glyceryl diformate,glyceryl triformate, triethylene glycol diformate and formate esters ofpentaerythritol.

The pH control additive also may comprise a base to elevate the pH ofthe treatment fluid. Generally, a base may be used to elevate the pH ofthe mixture. Any known base that is compatible with the viscosifyingagents of the present invention can be used in the treatment fluids ofthe present invention. Examples of suitable bases include, but are notlimited to, sodium hydroxide, potassium carbonate, potassium hydroxide,sodium carbonate, and sodium bicarbonate. One of ordinary skill in theart with the benefit of this disclosure will recognize the suitablebases that may be used to achieve a desired pH elevation.

In some embodiments, the treatment fluids of the present invention mayinclude surfactants, e.g., to improve the compatibility of the treatmentfluids of the present invention with other fluids (like any formationfluids) that may be present in the well bore. One of ordinary skill inthe art with the benefit of this disclosure will be able to identify thetype of surfactant as well as the appropriate concentration ofsurfactant to be used. Suitable surfactants may be used in a liquid orpowder form. Where used, the surfactants may be present in the treatmentfluid in an amount sufficient to prevent incompatibility with formationfluids, other treatment fluids, or well bore fluids. In an embodimentwhere liquid surfactants are used, the surfactants are generally presentin an amount in the range of from about 0.01% to about 5.0% by volume ofthe treatment fluid. In other embodiments, the liquid surfactants arepresent in an amount in the range of from about 0.1% to about 2.0% byvolume of the treatment fluid. In embodiments where powdered surfactantsare used, the surfactants may be present in an amount in the range offrom about 0.001% to about 0.5% by weight of the treatment fluid.

In some embodiments, the surfactant may be a viscoelastic surfactant.These viscoelastic surfactants may be cationic, anionic, nonionic,amphoteric, or zwitterionic in nature. The viscoelastic surfactants maycomprise any number of different compounds, including methyl estersulfonates (e.g., as described in U.S. Patent Application Nos.2006/0180310, 2006/0180309, 2006/0183646 and U.S. Pat. No. 7,159,659,the relevant disclosures of which are incorporated herein by reference),hydrolyzed keratin (e.g., as described in U.S. Pat. No. 6,547,871, therelevant disclosure of which is incorporated herein by reference),sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylatedfatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate,ethoxylated nonyl phenol), ethoxylated fatty amines, ethoxylated alkylamines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines,alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammoniumcompounds (e.g., trimethyltallowammonium chloride, trimethylcocoammoniumchloride), derivatives thereof, and combinations thereof. In certainembodiments, the surfactant may comprise a compliant surfactant such assodium lauryl sulfate, polyoxyethylene (20) sorbitan monolaurate(commonly known as Polysorbate 20 or Tween 20), polysorbate 60polysorbate 65, polysorbate 80, or sorbitan monostearate.

It should be noted that, in some embodiments, it may be beneficial toadd a surfactant to a treatment fluid of the present invention as thatfluid is being pumped downhole to help eliminate the possibility offoaming. However, in those embodiments where it is desirable to foam thetreatment fluids of the present invention, surfactants such as HY-CLEAN(HC-2) surface-active suspending agent or AQF-2 additive, bothcommercially available from Halliburton Energy Services, Inc., ofDuncan, Okla., may be used. Additional examples of foaming agents thatmay be utilized to foam and stabilize the treatment fluids of thisinvention include, but are not limited to, betaines, amine oxides,methyl ester sulfonates, alkylamidobetaines such as cocoamidopropylbetaine, alpha-olefin sulfonate, trimethyltallowammonium chloride, C₈ toC₂₂ alkylethoxylate sulfate and trimethylcocoammonium chloride. Othersuitable foaming agents and foam stabilizing agents may be included aswell, which will be known to those skilled in the art with the benefitof this disclosure.

In some embodiments of the present invention the treatment fluids maycomprise breakers in addition to the dual functional additives describedherein. Examples of such suitable breakers for treatment fluids of thepresent invention include, but are not limited to, sodium chlorites,hypochlorites, perborate, persulfates, peroxides, including organicperoxides. Other suitable breakers include, but are not limited to,suitable acids and peroxide breakers, delinkers, as well as enzymes thatmay be effective in breaking viscosified treatment fluids. In somepreferred embodiments, the breaker may be a compliant breaker such ascitric acid, other acids or chelating molecules found in 21 CFR§§170-199 (e.g. tetrasodium EDTA 175.300), oxidizers found in 21 CFR§§170-199 (e.g. ammonium persulfate 175.150), enzymes found within 21CFR §§170-199 (e.g. cellulose enzymes 173.120). A breaker may beincluded in a treatment fluid of the present invention in an amount andform sufficient to achieve the desired viscosity reduction at a desiredtime. The breaker may be formulated to provide a delayed break, ifdesired. For example, a suitable breaker may be encapsulated if desired.Suitable encapsulation methods are known to those skilled in the art.One suitable encapsulation method involves coating the selected breakerin a porous material that allows for release of the breaker at acontrolled rate. Another suitable encapsulation method that may be usedinvolves coating the chosen breakers with a material that will degradewhen downhole so as to release the breaker when desired. Resins that maybe suitable include, but are not limited to, polymeric materials thatwill degrade when downhole.

A treatment fluid of the present invention may optionally comprise anactivator or a retarder to, among other things, optimize the break rateprovided by a breaker. Any known activator or retarder that iscompatible with the particular breaker used is suitable for use in thepresent invention. Examples of such suitable activators include, but arenot limited to, acid generating materials, chelated iron, copper,cobalt, and reducing sugars. Examples of suitable retarders includesodium thiosulfate, methanol, and diethylenetriamine. In someembodiments, the sodium thiosulfate may be used in a range of from about1 to about 100 lb/Mgal of treatment fluid. Note, as used herein, “poundsper thousand gallons” may be expressed as “lb/Mgal” or “pptg.” Apreferred range may be from about 5 to about 20 lb/Mgal. An artisan ofordinary skill with the benefit of this disclosure will be able toidentify a suitable activator or retarder and the proper concentrationof such activator or retarder for a given application.

In certain embodiments of the present invention, the breakers may beencapsulated by synthetic and natural waxes. Waxes having differentmelting points may be used in order to control the delay of breakingbased on the temperature of a specific subterranean operation. In anembodiment, the encapsulation of the breaker is performed by mixing thebreaker and wax above the melting temperature for the specific wax andthen extruding the composition to form small particles of theencapsulated material. The resulting product may be annealed by brieflyheating the product to the point of the coating to seal cracks in thecoating, thus preventing premature release. The encapsulation may alsobe achieved by melt spraying the wax on the breaker (e.g. citric acid)particles or by any other technique known by a person of ordinary skillin the art. If used, a breaker should be included in a treatment fluidof the present invention in an amount sufficient to facilitate thedesired reduction in viscosity in a treatment fluid. For instance,peroxide concentrations that may be used vary from about 0.1 to about 30gallons of peroxide per 1000 gallons of the treatment fluid. Similarly,for instance, when citric acid is used as a breaker, concentrations offrom 0.1 lb/Mgal to 30 lb/Mgal are appropriate.

In other embodiments, it may be desirable to use a compliantdual-functional additive without using a substantial amount of anotherbreaker. That is, to have at least about 75% to about 100% of theviscosity reduction be due to the use of the dual functional additiverather than to the use of an additional breaker.

In some embodiments of the present invention the treatment fluids maycomprise additional fluid loss control additives known in the art inaddition to the dual functional additives described herein. Examples ofsuch additional fluid loss control agents include, but are not limitedto, starches, silica flour, gas bubbles (energized fluid or foam),benzoic acid, soaps, resin particulates, relative permeabilitymodifiers, and other immiscible fluids. It is also known in the art touse a dispersion of diesel in fluid as a fluid loss control agent;however, its use may have negative environmental impacts. If included, afluid loss additive may be included in an amount of about 5 to about2000 lb/Mgal of the treatment fluid. In some embodiments, the fluid lossadditive may be included in an amount from about 10 to about 50 lb/Mgalof the treatment fluid. For some liquid additives that function as fluidloss additives, these may be included in an amount from about 0.01% toabout 20% by volume; in some embodiments, these may be included in anamount from about 1.0% to about 10% by volume.

However, in other embodiments, it may be desirable to use a compliantdual-functional additive without using a substantial amount of anotherfluid loss control additive. That is, to have at least about 75% toabout 100% of the fluid loss control be due to the use of the dualfunctional additive rather than to the use of an additional fluid losscontrol additive.

In other embodiments, it may be desirable to use a compliantdual-functional additive without using a substantial amount of anotherfluid loss control additive or a substantially amount of anotherbreaker. That is, to have at least about 75% to about 100% of the fluidloss control and 75-100% of the viscosity reduction be due to the use ofthe dual functional additive rather than to the use of an additionalfluid loss control additive or breaker.

The methods and treatment fluids of the present invention may be usedduring or in preparation for any subterranean operation wherein a fluidmay be used. Suitable subterranean operations may include, but are notlimited to, drilling operations, drill-in operations, fracturingoperations, sand control treatments (e.g., gravel packing), acidizingtreatments (e.g., matrix acidizing, fracture acidizing, removal offilter cakes and fluid loss pills), “frac-pack” treatments, well boreclean-out treatments, and other suitable operations where a treatmentfluid of the present invention may be useful. One of ordinary skill inthe art, with the benefit of the present disclosure, will recognizesuitable operations in which the treatment fluids of the presentinvention may be used.

When selected dual-functional additive is in a liquid form, it ispreferably dispersed into the aqueous base fluid such that it forms“particles” or “beads” of dual-functional additive within the continuousphase of the aqueous base fluid. It is within the ability of one skilledin the art to disperse a selected dual-functional additive liquid intothe aqueous base fluid.

In certain embodiments, the present invention provides methods thatinclude a method comprising: providing a fracturing fluid comprising anaqueous base fluid, a viscosifying agent, and a compliantdual-functional additive; and introducing the fracturing fluid into atleast a portion of a subterranean formation at a rate and pressuresufficient to create or enhance at least one or more fractures in thesubterranean formation. In these embodiments, a treatment fluid of thepresent invention may be pumped into a well bore that penetrates asubterranean formation at a sufficient hydraulic pressure to create orenhance one or more cracks, or “fractures,” in the subterraneanformation. “Enhancing” one or more fractures in a subterraneanformation, as that term is used herein, is defined to include theextension or enlargement of one or more natural or previously createdfractures in the subterranean formation. The treatment fluids of thepresent invention used in these embodiments optionally may compriseparticulates, often referred to as “proppant particulates,” that may bedeposited in the fractures. The proppant particulates may function toprevent one or more of the fractures from fully closing upon the releaseof hydraulic pressure, forming conductive channels through which fluidsmay flow to the well bore. Once at least one fracture is created and theproppant particulates are substantially in place, the viscosity of thetreatment fluid of the present invention may be reduced (e.g., throughthe use of a gel breaker, or allowed to reduce naturally over time) toallow it to be recovered.

In certain embodiments, the treatment fluids of the present inventionmay be used in acidizing and/or acid fracturing operations. In theseembodiments, a portion of the subterranean formation is contacted with atreatment fluid of the present invention comprising one or more organicacids (or salts thereof) and one or more inorganic acids that interactwith subterranean formation to form “voids” (e.g., cracks, fractures,wormholes, etc.) in the formation. After acidization is completed, thetreatment fluid of the present invention (or some portion thereof) maybe recovered to the surface. The remaining voids in the subterraneanformation may enhance the formation's permeability, and/or increase therate at which fluids subsequently may be produced from the formation. Incertain embodiments, a treatment fluid of the present invention may beintroduced into the subterranean formation at or above a pressuresufficient to create or enhance one or more fractures within thesubterranean formation. In other embodiments, a treatment fluid of thepresent invention may be introduced into the subterranean formationbelow a pressure sufficient to create or enhance one or more fractureswithin the subterranean formation.

In certain embodiments, the present invention provides methods thatinclude a method comprising: providing a treatment fluid comprising anaqueous base fluid, a viscosifying agent, and a compliantdual-functional additive; introducing the treatment fluid into at leasta portion of the subterranean formation and allowing the dual-functionaladditive to minimize fluid loss by obstructing pore throats within thesubterranean formation.

In certain embodiments, the present invention provides methods thatinclude a method comprising: providing a treatment fluid comprising anaqueous base fluid, a viscosifying agent, and a compliantdual-functional additive; introducing the treatment fluid into at leasta portion of the subterranean formation and allowing the formation of afilter cake in the range of less than about 1 mm. The filter cake formedby the treatment fluids of the present invention may be a“self-degrading” filter cake. As referred to herein, the term“self-degrading filter cake” will be understood to mean a filter cakethat may be removed without the need to circulate a separate a clean-upsolution. Though the filter cakes formed by the treatment fluids of thepresent invention constitute self-degrading filter cakes, an operatormay choose to circulate a separate clean up solution through the wellbore under certain circumstances, such as when the operator desires tohasten the rate of degradation of the filter cake.

To facilitate a better understanding of the present invention, thefollowing examples of the preferred embodiments are given. In no wayshould the following examples be read to limit, or define, the scope ofthe invention.

EXAMPLES

The following examples are submitted for the purpose of demonstratingthe performance characteristics of the treatment fluids of the presentinvention.

Example 1

Initially the viscosity of a treatment fluid that did not contain a dualfunctional additive (such as either a triethyl citrate (TEC), ethylformate (EF), amyl formate (AF), triacetin (TA), or diethyl malonate(DEM)) was obtained to provide a reference point for comparison. Thesamples were prepared by dissolving 1.080 g of Cekol 30000 in 150 g oftap water with shear in a small, glass blender jar. After hydrating fora minimum of 30 minutes, the esters were added at the concentrations asnoted, followed by 1.4 ml (0.93% v/v) of aluminum crosslinker. All gelswere strongly crosslinked upon addition of the crosslinker. Table 1lists the prepared sample treatment fluids and their pH values.

TABLE 1 Prepared Sample Treatment Fluids and pH Values Ester Fluidinitial pH none 4.57  5 gal/Mgal TEC 4.18 50 gal/Mgal TEC 3.80 50gal/Mgal TEC + 10 gal/Mgal EF 3.79  5 gal/Mgal TEC + 10 gal/Mgal EF 4.37

Next, the viscosity of the treatment fluid above further containing 5gal/Mgal of TEC and 50 gal/Mgal of TEC and, optionally, 10 gal/Mgal ofEF were also measured. Viscosity was measured on a Chandler model 5550fitted with a B5X bob and R1 rotor. A constant shear rate of 40 sec⁻¹was used in all tests. The test temperature was 180° F. The maximumheating rate was used to heat the sample from ambient temperature to thetest temperature. FIG. 1 is a plot of viscosity curves as a function oftime for the treatment fluids. Both the FIG. 1 and the data show that acombination of TEC and EF lead to a more rapid breaking of the viscositywith lower concentrations of TEC. This should allow the treatment fluidto be more cost efficient and generate desired viscosity adequate fortransport and placement during a subterranean operation.

Example 2

Treatment fluids were prepared containing Aluminum-crosslinked 60lb/Mgal CMC gel with one or more of the following dual-functionaladditives: TEC, amyl formate (AF), triacetin (TA), or diethyl malonate(DEM). For each fluid, the esters were present in the treatment fluid inthe form of small droplets. Testing to determine final viscosity and pHwas performed and the results show that each of the testeddual-functional additives (esters) used with this invention were capableof reducing the viscosity of the treatment fluid. As can be seen inTable 1, advantageous results were found using a combination of TEC andAF. In addition, TA also improved the viscosity break. DEM wassufficient to break the gel upon release of malonic acid. The resultsare shown in Table 2. The sample treatment fluids were prepared with thesame polymer and crosslinker concentration as in example 1. All of thefluids initially were crosslinked gels. For the static break testprocedure, the samples were placed in 8 oz Falcon cups, capped, and setin a water bath at the indicated test temperature for the specifiedtime. After breaking, the viscosity was measured on a Haake RS150 fittedwith a Z40 Couette system at a shear rate of 40 sec⁻¹ and a temperatureof 25° C.

TABLE 2 Static Break Values for CMC gel containing TEC, AF, TA, and DEMFinal Temperature Time Viscosity Breaker (° F.) (hr) (@ 40 sec⁻¹) FinalpH 10 gal/Mgal AF 180 18 140 3.40 20 gal/Mgal AF 180 18 36 3.21  5gal/Mgal TEC 180 18 420 4.28  5 gal/Mgal TEC, 180 18 62 3.45 10 gal/MgalAF  5 gal/Mgal TEC, 180 18 18 3.17 20 gal/Mgal AF  5 gal/Mgal TEC, 18024 21 3.32 10 gal/Mgal TA  5 gal/Mgal TEC, 180 23 25 3.87 10 gal/Mgal TA 5 gal/Mgal TEC, 180 23 25 3.80 20 gal/Mgal TA 20 gal/Mgal DEM 180 21 6—

Example 3

Treatment fluids containing 60 lb/Mgal Al-crosslinked CMC with andwithout TEC were prepared. In addition, treatment fluids containing 40lb/Mgal Hybor G (a borate crosslinked guar available from HalliburtonEnergy Services, Inc. of Duncan, Okla.) were used as a comparison. Thefluid loss properties of the treatment fluids were tested. FIG. 2 is aplot of dynamic fluid loss curves as a function of time for thetreatment fluids and it shows that fluid loss was about half of thatobserved by the 40 lb/Mgal Hybor G treatment fluid. Thus, the dualfunctional additives of the present invention are capable of acting afluid loss control agents.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the specified range is alsosuitable for use in the present invention and is hereby specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

1. A method comprising: providing a treatment fluid comprising anaqueous base fluid, a viscosifying agent, and a compliantdual-functional additive; and introducing the treatment fluid into atleast a portion of the subterranean formation.
 2. The method of claim 1wherein the compliant dual-functional additive restricts the flow of afluid through pore throats within the subterranean formation.
 3. Themethod of claim 1 wherein the compliant dual-functional additivecomprises an ester selected from the group consisting of: ethyl formate,propyl formate, butyl formate, amyl formate, anisyl formate, methylacetate, propyl acetate, triacetin, butyl propionate, isoamylpropionate, ethyl lactate, methyl butyrate, ethyl isobutyrate, butylisobutyrate, diethyl malonate, butyl ethyl malonate, dimethyl succinate,diethyl succinate, diethyl malate, diethyl tartrate, dimethyl tartrate,triethyl citrate, and any combination thereof.
 4. The method of claim 1wherein the compliant dual-functional additive degrades to form an acid,and the acid acts as a viscosity reducing agent for the treatment fluid.5. The method of claim 4 wherein the acid is selected from the groupconsisting of: formic acid, acetic acid, propionic acid, lactic acid,butyric acid, isobutyric acid, malonic acid, succinic acid, malic acid,tartaric acid, citric acid, and any combination thereof.
 6. The methodof claim 1 wherein the viscosifying agent is selected from the groupconsisting of: a carboxymethylguar, a carboxymethylhydroxyethylguar, acarboxymethylhydroxypropylguar, a hydroxyethyl cellulose, acarboxyethylcellulose, a carboxymethylcellulose, acarboxymethylhydroxyethylcellulose, diutan gum, a xanthan gum, agalactomannan, a cellulose derivative, a hydroxyethylguar, ahydroxypropylguar, a scleroglucan, a wellan, a starch, an acrylamide, anacrylate and any derivative and combination thereof.
 7. The method ofclaim 1 wherein the viscosifying agent is crosslinked.
 8. The method ofclaim 1 wherein a self-degrading filter cake is formed.
 9. A methodcomprising: providing a fracturing fluid comprising an aqueous basefluid, a viscosifying agent, and a compliant dual-functional additivethat acts as a fluid loss control agent and a breaker; and introducingthe fracturing fluid into at least a portion of a subterranean formationat a rate and pressure sufficient to create or enhance at least one ormore fractures in the subterranean formation.
 10. The method of claim 9wherein the compliant dual-functional additive comprises an esterselected from the group consisting of: ethyl formate, propyl formate,butyl formate, amyl formate, anisyl formate, methyl acetate, propylacetate, triacetin, butyl propionate, isoamyl propionate, ethyl lactate,methyl butyrate, ethyl isobutyrate, butyl isobutyrate, diethyl malonate,butyl ethyl malonate, dimethyl succinate, diethyl succinate, diethylmalate, diethyl tartrate, dimethyl tartrate, triethyl citrate, and anycombination thereof.
 11. The method of claim 9 wherein the compliantdual-functional additive degrades to form an acid, and the acid acts asa viscosity reducing agent for the fracturing fluid.
 12. The method ofclaim 11 wherein the acid is selected from the group consisting of:formic acid, acetic acid, propionic acid, lactic acid, butyric acid,isobutyric acid, malonic acid, succinic acid, malic acid, tartaric acid,citric acid, and any combination thereof.
 13. The method of claim 9wherein the viscosifying agent is selected from the group consisting ofa carboxymethylguar, a carboxymethylhydroxyethylguar, acarboxymethylhydroxypropylguar, a hydroxyethylcellulose, acarboxyethylcellulose, a carboxymethylcellulose, acarboxymethylhydroxyethylcellulose, diutan gum, a xanthan gum, agalactomannan, a cellulose derivative, a hydroxyethylguar, ahydroxypropylguar, scleroglucan, a wellan, a starch, an acrylamide, anacrylate and any derivative and combination thereof.
 14. The method ofclaim 9 wherein the viscosifying agent is crosslinked.
 15. A methodcomprising: providing a treatment fluid comprising an aqueous basefluid, a viscosifying agent, and a compliant dual-functional additivethat comprises a fluid loss control agent and a breaker; introducing thetreatment fluid into at least a portion of the subterranean formation;and allowing the dual-functional additive to minimize fluid loss byobstructing at least one pore throat in the subterranean formation. 16.The method of claim 15 wherein the compliant dual-functional additivecomprises an ester selected from the group consisting of: ethyl formate,propyl formate, butyl formate, amyl formate, anisyl formate, methylacetate, propyl acetate, triacetin, butyl propionate, isoamylpropionate, ethyl lactate, methyl butyrate, ethyl isobutyrate, butylisobutyrate, diethyl malonate, butyl ethyl malonate, dimethyl succinate,diethyl succinate, diethyl malate, diethyl tartrate, dimethyl tartrate,triethyl citrate, and any combination thereof.
 17. The method of claim15 wherein the compliant dual-functional additive releases an acid andthe acid interacts with the viscosifying agent so as to reduce theviscosity of the treatment fluid.
 18. The method of claim 17 wherein theacid is selected from the group consisting of: formic acid, acetic acid,propionic acid, lactic acid, butyric acid, isobutyric acid, malonicacid, succinic acid, malic acid, tartaric acid, citric acid, and anycombination thereof.
 19. The method of claim 15 wherein the viscosifyingagent is selected from the group consisting of: a carboxymethylguar, acarboxymethylhydroxyethylguar, a carboxymethylhydroxypropylguar, ahydroxyethylcellulose, a carboxyethylcellulose, acarboxymethylcellulose, a carboxymethylhydroxyethylcellulose, diutangum, a xanthan gum, a galactomannan, a cellulose derivative, ahydroxyethylguar, a hydroxypropylguar, a scleroglucan, a wellan, astarch, an acrylamide, an acrylate and any derivative and combinationthereof.
 20. The method of claim 15 wherein a self-degrading filter cakeis formed.